Self-calibrated ultrasonic method of in-situ measurement of borehole fluid acoustic properties

ABSTRACT

Tools and methods are provided that determine the acoustic impedance of drilling fluid using reflections from a precise metal disk. Because the reverberation characteristics of an acoustic wave depend in part on the acoustic wave shape, the first reflection from the metal disk may be used to calibrate the measurement. A method for determining a borehole fluid property includes (i) generating an acoustic signal within a borehole fluid, (ii) receiving reflections of the acoustic signal from the fluid, and (iii) analyzing a reverberation portion of the acoustic signal to determine the property. The analyzing of the reverberation portion may include obtaining a theoretical reverberation signal and relating the measured reverberation signal with the theoretical reverberation signal to determine the borehole fluid property.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.09/927,067 which was filed Aug. 9, 2001 now U.S. Pat. No. 6,712,138.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to oil well logging andmonitoring. More particularly, the present invention relates todetermining the acoustic properties of a borehole fluid.

2. Description of the Related Art

To recover oil and gas from subsurface formations, wellbores orboreholes are drilled by rotating a drill bit attached at an end of adrill string. The drill string includes a drill pipe or a coiled tubingthat has a drill bit at its downhole end and a bottom hole assembly(BHA) above the drill bit. The wellbore is drilled by rotating the drillbit by rotating the tubing and/or by a mud motor disposed in the BHA. Adrilling or wellbore fluid commonly referred to as the “mud” is suppliedunder pressure from a surface source into the tubing during drilling ofthe to wellbore. The drilling fluid operates the mud motor (when used)and discharges at the drill bit bottom. The drilling fluid then returnsto the surface via the annular space (annulus) between the drill stringand the wellbore wall or inside. Fluid returning to the surface carriesthe rock bits (cuttings) produced by the drill bit as it disintegratesthe rock to drill the wellbore.

A wellbore is overburdened when the drilling fluid column pressure isgreater than the formation pressure. In overburdened wellbores, some ofthe drilling fluid penetrates into the formation, thereby causing a lossin the drilling fluid and forming an invaded zone around the wellbore.It is desirable to reduce the fluid loss into the formation because itmakes it more difficult to measure the properties of the virginformation, which are required to determine the presence andretrievability of the trapped hydrocarbons. In underbalanced drilling,the fluid column pressure is less than the formation pressure, whichcauses the formation fluid to enter into the wellbore. This invasion mayreduce the effectiveness of the drilling fluid.

A substantial proportion of the current drilling activity involvesdirectional boreholes (deviated and horizontal boreholes) and/or deeperboreholes to recover greater amounts of hydrocarbons from the subsurfaceformations and also to recover previously unrecoverable hydrocarbons.Drilling of such boreholes require the drilling fluid to have complexphysical and chemical characteristics. The drilling fluid is made up ofa base such as water or synthetic material and may contain a number ofadditives depending upon the specific application. A major component inthe success the drilling operation is the performance of the drillingfluid, especially for drilling deeper wellbores, horizontal wellboresand wellbores in hostile environments (high temperature and pressure).These environments require the drilling fluid to excel in manyperformance categories. The drilling operator and the mud engineerdetermine the type of the drilling fluid most suitable for theparticular drilling operations and then utilize various additives toobtain the desired performance characteristics such as viscosity,density, gelation or thixotropic properties, mechanical stability,chemical stability, lubricating characteristics, ability to carrycuttings to the surface during drilling, ability to hold in suspensionsuch cuttings when fluid circulation is stopped, environmental harmony,non-corrosive effect on the drilling components, provision of adequatehydrostatic pressure and cooling and lubricating impact on the drill bitand BHA components.

A stable borehole is generally a result of a chemical and/or mechanicalbalance of the drilling fluid. With respect to the mechanical stability,the hydrostatic pressure exerted by the drilling fluid in overburdenedwells is normally designed to exceed the formation pressures. This isgenerally controlled by controlling the fluid density at the surface. Todetermine the fluid density during drilling, the operators take intoaccount prior knowledge, the behavior of rock under stress, and theirrelated deformation characteristics, formation dip, fluid velocity, typeof the formation being drilled, etc. However, the actual density of thefluid is not continuously measured downhole, which may be different fromthe density assumed by the operator. Further, the fluid density downholeis dynamic, i.e., it continuously changes depending upon the actualdrilling and borehole conditions, including the downhole temperature andpressure. Thus, it is desirable to determine density of the wellborefluid downhole during the drilling operations and then to alter thedrilling fluid composition at the surface to obtain the desired densityand/or to take other corrective actions based on such measurements.

As noted above, an important function of the drilling fluid is totransport cuttings from the wellbore as the drilling progresses. Oncethe drill bit has created a drill cutting, it should be removed fromunder the bit. If the cutting remains under the bit it is redrilled intosmaller pieces, adversely affecting the rate of penetration, bit lifeand mud properties. The annular velocity needs to be greater than theslip velocity for cuttings to move uphole. The size, shape and weight ofthe cuttings determine the viscosity necessary to control the rate ofsettling through the drilling fluid. Low shear rate viscosity controlsthe carrying capacity of the drilling fluid. The density of thesuspending fluid has an associated buoyancy effect on cuttings. Anincrease in density usually has an associated favorable affect on thecarrying capacity of the drilling fluid. In horizontal wellbores,heavier cuttings can settle on the bottom side of the wellbore if thefluid properties and fluid speed are not adequate. Cuttings can alsoaccumulate in washed-out zones. Determining the density of the fluiddownhole provides an indication of whether cuttings are settling oraccumulating at any place in the wellbore.

In the oil and gas industry, various devices and sensors have been usedto determine a variety of downhole parameters during drilling ofwellbores. Such tools are generally referred to as themeasurement-while-drilling (MWD) tools. The general emphasis of theindustry has been to use MWD tools to determine parameters relating tothe formations, physical condition of the tool and the borehole. Veryfew measurements are made relating to the drilling fluid. The majorityof the measurements relating to the drilling fluid are made at thesurface by analyzing samples collected from the fluid returning to thesurface. Corrective actions are taken based on such measurements, whichin many cases take a long time and do not represent the actual fluidproperties downhole.

SUMMARY OF THE INVENTION

The problems outlined above are in large part addressed by aself-calibrated ultrasonic method of in-situ measurement of boreholefluid acoustic properties. In a preferred embodiment of the presentinvention, a method for determining a borehole fluid property includes(i) generating an acoustic signal within a borehole fluid, (ii)receiving reflections of the acoustic signal from the fluid, and (iii)analyzing a reverberation portion of the acoustic signal to determinethe property. The analyzing of the reverberation portion may includeobtaining a theoretical reverberation signal and relating the measuredreverberation signal with the theoretical reverberation signal todetermine the borehole fluid property.

In another preferred embodiment of the present invention, a processoradapted to provide real-time estimates of a borehole fluid propertyincludes an input terminal and a processing portion. The input terminalreceives a data signal corresponding to a reflected acoustic wave. Theprocessing portion separates the data signal into a first reflectionportion and a resonance portion and convolves the first reflectionportion response to yield a theoretical reverberation response.

In yet another preferred embodiment of the present invention, a tool formeasuring borehole fluid properties includes a body, an acoustictransducer, and a metal disk. The body houses the transducer and metaldisk. A borehole fluid enters the tool through an opening in the body,flows in between the transducer and metal disk where it is measured, andexits the tool.

Thus, the present invention comprises a combination of features andadvantages which enable it to overcome various problems of priordevices. The various characteristics described above, as well as otherfeatures, will be readily apparent to those skilled in the art uponreading the following detailed description of the preferred embodimentsof the invention, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the preferred embodiment of thepresent invention, reference will now be made to the accompanyingdrawings, wherein:

FIG. 1A is a general schematic showing a tool in a preferred embodiment;

FIG. 1B is a cut-away view illustrating component parts of FIG. 1A;

FIG. 2 illustrates waveform reflection and reverberation;

FIG. 3 is a graph showing a received acoustic waveform;

FIG. 4 is a diagram illustrating the component parts of FIG. 3;

FIG. 5A is a diagram of a subterranean system built in accord with apreferred embodiment;

FIG. 5B is a diagram of the above ground system built in accord with apreferred embodiment;

FIG. 6 is a general flow diagram of a preferred embodiment;

FIG. 7A is a flow diagram of a preferred embodiment; and

FIG. 7B is a flow diagram of a preferred embodiment.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

FIG. 1A illustrates a general overview of a tool submerged downhole.Shown are tool 10, fluid vent 20, formation 30, and well fluid 210.Fluid vent 20 provides a means for well fluid 210 to enter and exit tool10. While in tool 10, well fluid 210 is measured for its acousticproperties.

FIG. 1B is a cross-sectional view of the tool showing acousticmeasurement components. Inside tool 10, where fluid vent 20 is located,are acoustic transducer 200 and metal disk 220. As can be seen, wellfluid 210 enters tool 10, flows between acoustic transducer 200 andmetal disk 220, and exits tool 10.

FIG. 2 illustrates the acoustic wave path and metal disk reverberationsfor a downhole acoustic wave. Shown are acoustic transducer 200, wellfluid 210 and metal disk 220. Well fluid 210 and disk 220 each has itsown impedance, labeled Z_(m) and Z_(s), respectively. Also shown isacoustic signal 250, including first reflected portion 260, diskreverberation portions 271-276 and transmitted wave portions 280, 282,284 and 286 through the disk in the same well fluid.

To measure the reflection coefficient of the well fluid, the acoustictransducer 200 sends out acoustic signal 250, which is preferably anultrasonic impulse with a characteristic frequency of about 500 kHz,then switches to the receive mode. The impulse frequency is preferablyset at the expected resonance frequency of the disk. The acoustic signal250 travels through the well fluid 210 and strikes the disk 220. Thelargest portion of the energy of the impulse is reflected back to thetransducer as reflected portion 260 while a small amount of signalenters the disk as wave 280. When the well fluid 210 is water, thereflected wave form has an amplitude of about 93% of the initialimpulse. The portion of the signal that entered the disk is reflectedback and forth between the disk/fluid interface and the disk/toolinterface, as illustrated by wave reverberations 271-276. At eachreflection some energy is transmitted through the interface, dependenton the acoustic impedance contrast, and is either directed back towardthe transducer or out into the tool. The signal inside the disk isquickly dissipated in this manner at a rate directly dependent on theacoustic impedance of the material outside the disk according to theequation:R ₁=(Z ₁ −Z ₂)/(Z ₁ +Z ₂)  (1)where R₁ is the reflection coefficient, and Z₁ and Z₂ are the impedancesof the materials at the interface in question. In a preferredembodiment, the thickness of the metal disk is set to one half of theresonant wavelength of the transducer signal.

The acoustic transducer 200, now acting as a receiver or transducer,sees a waveform consisting of a loud initial reflection followed by anexponentially decaying reverberation signal. FIG. 3 illustrates themeasured acoustic waveform received at the transducer 200. If time t=0is the time of generation of the acoustic wave at the acoustictransmitter, then the time T_(tran) represents the transit time (thetime for the travel of this acoustic wave to the disk and back to thetransceiver). Since the distance is fixed, the transit time T_(tran)provides an indication of the acoustic velocity of the fluid. Also shownin FIG. 3 are the Time Offset, T_(off), and the Resonance Window,T_(win), both of whose significance is explained below.

FIG. 4 illustrates the individual waveforms, both first reflection andreverberations, that sum to provide the waveform of FIG. 3. The waveformreceived by the transducer is the sum of the initial reflection waveformwith each reverberation waveform, where each reverberation is delayed anamount proportional to the width of the disk. Further, because theacoustic transducer is not a perfect transmitter, it “rings” somewhatupon the transmission of an acoustic wave. This transducer “ringing”also is included in the detected waveform, and may be accounted for bythe present invention.

FIG. 5 illustrates a device built in accord with a preferred embodiment.Shown in FIG. 5A is acoustic transducer 200, analog-to-digital converter500, a processor 510 for recording start time and gain, waveformcompression chip 520, and multiplexer 530. Waveform compression chip 520could alternately be part of a processor. Also shown are downholetransmitter 540 connected to multiplexer 530 and telemetry cable 545.Referring now to FIG. 5B, at the surface are located uphole receiver550, demultiplexer 560, transmission line 564 carrying tool informationto processor 590 for a data log 595, transmission line 570 carrying gainand start time information to uphole processor 590, and waveformdecompression chip 580. Attached to decompression chip 580 is processor590. Processor 590 generates data suitable for a log 595.

Referring now to both FIGS. 5A and 5B, acoustic transducer 200 collectsdata of metal disk reflection and reverberation. This acoustic waveformis digitized by analog-to-digital converter 500 and sent to processor510, which detects the first reflection from the digitized signal.Processor 510 then computes the relevant start time and transit time.Because the total waveform data may be greater than the bandwidthcapacity of transmission line 545, digital compression 520 is preferablyperformed. Suitable compressions include wavelet and ADPCM (AdaptiveDifferential Pulse Code Modulation) techniques, which work well forsmoothly varying data. The compressed waveform from digital compressionchip 520 is then multiplexed 530 with the other tool information.Downhole transmitter 540 sends this multiplexed data to the surface.Sending the data to the surface allows processing by faster, moresophisticated machinery.

Referring now to both FIGS. 5A and 5B, acoustic transceiver 200 collectsdata of metal disk reflection and reverberation. This acoustic waveformis digitized by analog-to-digital converter 500 and sent to processor510, which detects the first reflection from the digitized signal.Processor 510 then computes the relevant start time and transit time.Because the total waveform data may be greater than the bandwidthcapacity of transmission line 545, digital compression 520 is preferablyperformed. Suitable compressions include wavelet and ADPCM (AdaptiveDifferential Pulse Code Modulation) techniques, which work well forsmoothly varying data. The compressed waveform from digital compressionchip 520 is then multiplexed 530 with the other tool information.Downhole transmitter 540 sends this multiplexed data to the surface.Sending the data to the surface allows processing by faster, moresophisticated machinery.

This multiplexed data is received by uphole receiver 550 and isseparated into component parts by demultiplexer 560. Waveformdecompression chip 580 provides the reconstructed waveform to processor590, which also receives start time information. Upon the determinationof the reflection coefficient of the well fluid, processor 590 combineswith position information and creates a log 595.

FIG. 6 illustrates a general method for the present invention. In block600, an observed waveform is provided uphole for processing. In someembodiments, it may be desirable to stack waveforms (block 610). Thewaveform's transit time (T_(tran)) is obtained in block 620, as well asthe time windows T_(off) and T_(win). The definition of transit time wasexplained above with reference to FIG. 3 and may be easily measured by afirst reflection detector portion of processor 510. T_(off) and T_(win)are then selected to obtain a time window T_(win) that contains reliablereverberation information. T_(off), measured from the time of receiptfor the initial reflection, is a time window that encompasses theinitial reflection. As such, its duration is dependent upon the durationof the acoustic impulse transmitted by acoustic transducer 200 and thenature of the drilling fluid. T_(off) also preferably accounts for errorintroduced because of the real-world shortcomings of the acoustictransducer (transducer “ringing”), and thus T_(off) may be slightlylonger than if chosen theoretically. Nonetheless, T_(off) is about 15microseconds. T_(win) is juxtaposed with T_(off) and is a time window ofinterest because T_(win) contains reverberation informationuncontaminated by the first reflection. The duration of T_(win) shouldbe brief enough so that noise and reverberations occurring in the tool10 do not make unreliable the received disk reverberation waveforms.Nonetheless, so that a reliable wave train containing sufficient data isobtained, T_(win) preferably includes at least four reverberations.Thus, T_(win) is about 12.8 microseconds.

The tool calibration may be obtained as follows. First, the reflectionwaveform defined by T_(off) is transformed to the frequency domain byuse of DFT (Discrete Fourier Transform). Referring back to FIG. 6,proper modeling applied to the first reflection portion 260, as definedby T_(off), gives a theoretical prediction of what the reverberationwaveform contained in T_(win) should look like. To accomplish this, inblock 630 the first reflection signal is transformed by Fast FourierTransform (FFT) into its frequency domain equivalent. This yields S(ω).Because the modeling is done in the frequency domain, amplitude andphase errors are eliminated. This error elimination simplifiesmathematical processing (and hence faster processing is obtained).

Alternately, instead of transforming each first reflection individually,to enhance accuracy, the first reflections from multiple firings mayfirst be averaged and the result transformed in block 630 by FFTprocessing into the frequency domain to yield S(ω). A most reliablefirst reflection average may be obtained by discarding first reflectionsthat have amplitudes above or below a preset deviation from a movingaverage of preceding first reflections.

In block 640, a theoretical prediction of the reverberation waves isobtained by multiplying (convolution in time domain) thefrequency-domain first reflection signal S(ω) with a frequency-domaintheoretical response equation R(ω) to obtain a frequency domain versionX(ω) of the reverberation signal x(t). Assuming a flat metal disk, thetheoretical frequency domain response may be modeled by the following:$\begin{matrix}{{R(\omega)} = {\frac{Z_{m} - Z_{s}}{Z_{m} + Z_{s}} + {\frac{\frac{4Z_{m}{Z_{s}\left( {Z_{s} - Z_{m}} \right)}}{\left( {Z_{m} + Z_{s}} \right)^{3}}}{1 - {\left( \frac{Z_{s} - Z_{m}}{Z_{m} + Z_{s}} \right)^{2}{\mathbb{e}}^{{- {\mathbb{i}}}\quad 2\omega\frac{C_{T}}{V_{s}}}}}{\mathbb{e}}^{{- {\mathbb{i}}}\quad 2\omega\frac{C_{T}}{V_{s}}}}}} & (2)\end{matrix}$Where

-   -   R(ω)=the reflection coefficient for angular frequency ω    -   Z_(m), Z_(s), =impedances for mud and metal disk, respectively    -   V_(s)=the speed of sound in the metal disk, and    -   C_(T)=the thickness of the metal disk.

The above equation assumes that the transducer generates waves havingnormal (i.e., perpendicular) incidence on the disk. V_(s), Z_(s), andC_(T) can be measured very precisely as basic physical properties of themetal disk.

In block 640 the frequency domain signal X(ω) is transformed back intothe time domain by use of an Inverse Fast Fourier Transform (IFFT). Assuch, block 640 provides the theoretical reverberation response x(t) forthe observed initial reflection waveform(s) in the time domain. Thistheoretical reverberation response is also a function of the boreholefluid impedance Z_(m). Once the results are converted to the timedomain, a relationship is established between the theoretical responseand the received response. Next, a method is used to determine theborehole fluid properties in block 650.

Two embodiments for relating theoretical and measured responses in block640 include 1) a curve fitting method and 2) a non-linear waveforminversion method. Both methods calculate theoretical waveform responsebased on Equation 2. However, the curve fitting method uses fewertheoretical modeling steps than the inversion method.

FIG. 7A illustrates the curve fitting method, where a measurementequation is determined. As an initial matter, for a reverberation windowof interest, T_(win) the natural log of the sum of the reverberationwaveform amplitude (S_(w)) varies linearly with well fluid impedance.That is, a linear relationship between well fluid impedance and S_(w)may be expressed as:Z _(m) =A+B1n(S _(w))  (3)where S_(w) is the sum of the reverberation waveform amplitudes and hasthe form: $\begin{matrix}{S_{w} = {\sum\limits_{t}^{\quad}\quad{{x(t)}}}} & (4)\end{matrix}$the lower case x(t) being the amplitude at any given point in thereverberation waveform contained in T_(win).

For the curve-fitting method, block 640 includes blocks 700-760. Inblock 700, an initial theoretical fluid impedance Z_(m) is chosen. Inblock 710, the theoretical response R(ω) is calculated in accordancewith Equation 2. In block 720, the first reflection is convolved withthe theoretical response obtained in block 710. In block 730, theInverse Fast Fourier Transform (IFFT) is performed to obtain atheoretical reverberation waveform. Next, the summed amplitudes of thetheoretical reverberation waveform S_(w) is determined in block 740. Inblock 750, the theoretical response R(ω) and reverberation waveformamplitude sum S_(w) are stored. In block 760, it is decided whether ornot additional data is needed. If additional data is necessary, anothertheoretical fluid impedance Z_(m) may be chosen in block 700. Todetermine the coefficients in this linear relationship, steps 700-760are repeated at least twice for different assumed fluid impedancesZ_(m). Each time, the resulting sum S_(w) is calculated. From thesemultiple points, (S_(w), Z_(m)), the coefficients A, B, can bedetermined using the least squares curve fitting in block 770. With therelationship, the measured impedance Z_(m) can be determined from theobserved S_(w) using Equation 4 in block 780.

Lastly, in block 650 (FIG. 6), S_(w) is substituted into Equation 3, andwell fluid impedance Z_(m), is determined. The acoustic velocity of thefluid may also be calculated in block 650. Because the separationbetween the transducer and disk is known, the velocity is calculablefrom the measured transit time T_(tran). From the impedance (ρ) andvelocity (v), the fluid density (Z_(m)) can be calculated due to therelationship: Z_(m)=ρv.

As mentioned above, in a second embodiment, non-linear waveforminversion may be used in block 640 to determine the relationship betweentheoretical and measured reverberation. While the waveform inversionmethod is slower than the curve fitting method described above, itproduces more accurate results because it matches entire reverberationwaveform window using both amplitude and phase. As a result, many fluidacoustic properties including density and attenuation can be calculatedsimultaneously. A preferred method employs the Levenberg-Marquardtmethod. See generally W. Press et al., Levenberg-Marquardt Method, p.542 (Numerical Recipes in C, 1988), incorporated herein by reference.

In the non-linear waveform inversion embodiment shown in FIG. 7B, fluidproperties such as velocity, density, and attenuation are initiallyestimated in block 800. In block 810, the theoretical response R(ω) iscalculated in accordance with Equation 2. In block 820, the firstreflection is convolved with the theoretical response obtained in block710. In block 830, the Inverse Fast Fourier Transform (IFFT) isperformed to obtain an estimated reverberation waveform. In block 840,the error between the estimated and measured waveforms is determined.The error is calculated according to Equation 5.Error=Σ|(observed-theoretical)²|  (5)

In block 850, the error calculated in block 840 is compared to apredetermined tolerance. If the calculated error is greater that thepredetermined tolerance, another estimate is performed in block 800using the Levenberg-Marquardt method. This cycle is repeated until thecalculated error is less than the predetermined tolerance. When thecalculated error is less than the predetermined tolerance, the estimatedfluid velocity, density, and attenuation are accepted as the measuredproperties in block 860.

While preferred embodiments of this invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit or teaching of this invention. Theembodiments described herein are exemplary only and are not limiting.For example, while the present invention has been described for usewhile drilling a well, it may also be used during completing andproducing. Many variations and modifications of the system and apparatusare possible and are within the scope of the invention. Accordingly, thescope of protection is not limited to the embodiments described herein,but is only limited by the claims that follow, the scope of which shallinclude all equivalents of the subject matter of the claims.

1. A tool for measuring one or more fluid properties that comprises: abody having an associated volume through which a fluid may pass; a knownsurface fixed within the volume to contact the fluid; an acoustictransducer affixed to the body and configured to receive acoustic signalreflections and reverberations from the known surface; and a processorcoupled to the acoustic transducer, wherein the processor calculatestheoretical acoustic signal reverberations by combining a frequencydomain response of the acoustic signal reflection with a theoreticalfrequency domain response of the known surface, and wherein theprocessor relates the received acoustic signal reverberations with thetheoretical acoustic signal reverberations to determine the one or morefluid properties.
 2. The tool of claim 1, wherein the known surface ismetallic.
 3. The tool of claim 1, wherein the known surface is steel. 4.The tool of claim 1, wherein the known surface is a metal disk.
 5. Thetool of claim 1, wherein the one or more fluid properties includesacoustic impedance.
 6. The tool of claim 1, wherein the acoustictransducer is further configured to generate acoustic signals thatimpinge on the known surface to cause said acoustic signal reflectionsand reverberations.
 7. The tool of claim 6, wherein the processormeasures a time delay between the generation of the acoustic signals andthe receiving of the acoustic signals to determine an acoustic velocity.8. The tool of claim 1, wherein the one or more fluid propertiesincludes fluid density.
 9. A tool for measuring one or more fluidproperties that comprises: a body having an associated volume throughwhich a fluid may pass; a surface fixed within the volume to contact thefluid; and an acoustic transducer affixed to the body and configured toreceive acoustic signal reflections and reverberations from the surface,wherein the surface has opposite sides configured to contact the fluid,and wherein the surface is a metal disk.
 10. The tool of claim 9,further comprising a processor coupled to the acoustic transducer,wherein the processor calculates theoretical acoustic signalreverberations by combining a frequency domain response of the acousticsignal reflection with a theoretical frequency domain response of themetal disk, and wherein the processor relates the received acousticsignal reverberations with the theoretical acoustic signalreverberations to determine the one or more fluid properties.
 11. Thetool of claim 9, wherein the tool couples to a processor that measures atime delay between the generation of the acoustic signals and thereceiving of the acoustic signals to determine an acoustic velocity. 12.The tool of claim 9, wherein the one or more fluid properties includesacoustic impedance.
 13. The tool of claim 9, wherein the acoustictransducer is further configured to generate acoustic signals thatimpinge on the metal disk to cause said acoustic signal reflections andreverberations.
 14. The tool of claim 9, wherein the one or more fluidproperties includes fluid density.
 15. A tool for measuring one or morefluid properties that comprises: a body having an associated volumethrough which a fluid may pass; a metal plate with opposite sidesconfigured to contact the fluid, the plate being fixed within the volumeto contact the fluid; and an acoustic transducer affixed to the body andconfigured to receive acoustic signal reflections and reverberationsfrom the metal plate.
 16. The tool of claim 15, further comprising aprocessor coupled to the acoustic transducer, wherein the processorcalculates theoretical acoustic signal reverberations by combining afrequency domain response of the acoustic signal reflection with atheoretical frequency domain response of the metal plate, and whereinthe processor relates the received acoustic signal reverberations withthe theoretical acoustic signal reverberations to determine the one ormore fluid properties.
 17. The tool of claim 15, wherein the toolcouples to a processor that measures a time delay between the generationof the acoustic signals and the receiving of the acoustic signals todetermine an acoustic velocity.
 18. The tool of claim 15, wherein theone or more fluid properties includes acoustic impedance.
 19. The toolof claim 15, wherein the acoustic transducer is further configured togenerate acoustic signals that impinge on the metal plate to cause saidacoustic signal reflections and reverberations.
 20. The tool of claim15, wherein the one or more fluid properties includes fluid density.